EP3317240A1 - Methods of cryogenic purification, ethane separation, and systems related thereto - Google Patents

Abstract

Methods of cryogenically purifying process streams are disclosed herein, including methods of separating carbon dioxide from a process stream and condensing a primary component of the process stream and methods of separating carbon dioxide from a process stream without condensing a primary component of the process stream. Systems for cryogenically purifying process streams are disclosed herein, including systems for separating carbon dioxide from a process stream and condensing a primary component of the process stream and systems for separating carbon dioxide from a process stream without condensing a primary component of the process stream. Methods and systems for separating ethane from carbon dioxide are also disclosed herein.

Description

METHODS OF CRYOGENIC PURIFICATION, ETHANE SEPARATION, AND

SYSTEMS RELATED THERETO

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application claims priority to United States Provisional Patent Application

No. 62/157,889, entitled "METHODS OF CRYOGENIC PURIFICATION AND

SYSTEMS RELATED THERETO," filed May 6, 2015 and to United States Provisional

Patent Application No. 62/387,322, entitled "METHODS OF CRYOGENIC

PURIFICATION, ETHANE SEPARATION, AND SYSTEMS RELATED THERETO," filed

December 23, 2015, the contents of both of which are hereby incorporated herein by reference in their entirety

TECHNICAL FIELD

[0002] The present disclosure relates generally to industrial processes. More specifically, the present disclosure relates to methods of cryogenically purifying process streams, separating ethane from carbon dioxide, and systems related thereto.

BRIEF DESCRIPTION OF THE DRAWINGS [0003] The written disclosure herein describes illustrative embodiments that are non- limiting and non-exhaustive. Reference is made to certain of such illustrative embodiments that are depicted in the figures, in which: [0004] FIG. 1 is a schematic diagram of one embodiment of a high-pressure or condensing natural gas processing system.

[0005] FIG. 2 is a schematic diagram of a simplified version of the processing system illustrated in Figure 1 .

[0006] FIG. 3 is a schematic diagram of a low-pressure process in which the major product does not condense.

[0007] FIG. 4 illustrates one method to lower the dissolved C0₂ content.

[0008] FIG. 5 illustrates a variation of conventional two-column extractive distillation used to separate C0₂ from ethane.

[0009] FIG. 6(a) depicts a temperature profile for extractive and recovery columns of the system of Figure 5.

[0010] FIG. 6(b) depicts a composition profile for extractive columns of the system of Figure 5.

[0011] FIG. 6(c) depicts a composition profile for recovery columns of the system of Figure 5.

[0012] FIG. 7 illustrates a flowsheet for an exemplary C0₂-ethane azeotrope separation.

[0013] FIG. 8(a) depicts a temperature profile for extractive and recovery columns of the system of Figure 7.

[0014] FIG. 8(b) depicts a composition profile for extractive columns of the system of Figure 7.

[0015] FIG. 8(c) depicts a composition profile for recovery columns of the the system of Figure 7. [0016] FIG. 9(a) depicts a graph showing the effect of solvent and reflux ratio on C0₂ purity.

[0017] FIG. 9(b) depicts a graph showing the effect of solvent and reflux ratio on a C0₂ impurity in the extractive column distillate.

[0018] FIG. 9(c) depicts a graph showing the effect of solvent and reflux ratio on another C0₂ impurity in the extractive column distillate.

DETAILED DESCRIPTION

[0019] Methods of cryogenically purifying process streams and systems related thereto are disclosed herein. It will be readily understood that the embodiments as generally described below and as illustrated in the examples and Figures could be modified in a wide variety of ways. Thus, the following more detailed description of various embodiments, as described below and represented in the examples and Figures, is not intended to limit the scope of the disclosure, but is merely representative of various embodiments.

[0020] The phrase "in communication with" and the term "connecting" refer to any form of interaction between two or more entities, including mechanical, electrical, magnetic, electromagnetic, fluid, and thermal interaction. Two entities may interact with each other even though they are not in direct contact with each other. For example, two entities may interact with each other through an intermediate entity.

[0021] Methods of cryogenically purifying process streams may comprise methods of separating carbon dioxide from a process stream and condensing a primary component of the process stream. Alternatively, methods of cryogenically purifying process streams may comprise methods of separating carbon dioxide from a process stream without condensing a primary component of the process stream.

[0022] In some embodiments of methods of separating carbon dioxide from a process stream and condensing a primary component of the process stream, the methods comprise providing a process stream comprising gaseous carbon dioxide and further comprising a primary component, wherein the process stream is at a first temperature and a first pressure. The methods further comprise cooling the process stream to at or below the condensation temperature of the primary component in the process stream. The methods may further comprise separating any gases from the process stream that did not condense during cooling the process stream to at or below the condensation temperature of the primary component to form a first separated gaseous stream. The methods further comprise cooling the process stream further to at or below the frost point of carbon dioxide in the process stream, thereby forming solid carbon dioxide, and separating physically solid carbon dioxide from the process stream to form a separated solid carbon dioxide slurry stream and a liquid primary component stream.

[0023] In some embodiments of separating carbon dioxide from a process stream without condensing a primary component of the process stream, the methods comprise providing a process stream comprising gaseous carbon dioxide and further comprising a primary component, wherein the process stream is at a first temperature and a first pressure. The methods further comprise reducing the temperature of the process stream to a temperature at or below the frost point of carbon dioxide in the process stream, by directly contacting the process stream with a colder contact liquid, thereby forming solid carbon dioxide in the contact liquid and forming a gaseous purified primary component stream. The methods may further comprise separating physically solid carbon dioxide from the contact liquid to form a solid carbon dioxide slurry stream from a purified contact liquid stream.

[0024] Systems for cryogenically purifying process streams may comprise systems for separating carbon dioxide from a process stream and condensing a primary component of the process stream. Systems for cryogenically purifying process streams may comprise systems for separating carbon dioxide from a process stream without condensing a primary component of the process stream.

[0025] In some embodiments of systems for separating carbon dioxide from a process stream and condensing a primary component of the process stream, the systems comprise a desublimation heat exchanger configured to receive a process stream comprising gaseous carbon dioxide and a primary component with a condensation temperature above the frost point of carbon dioxide at the pressure of the process stream, the desublimation heat exchanger further configured to cool the process stream to at or below the frost point of carbon dioxide in the process stream. The systems may further comprise a solid-liquid separator configured to physically separate a solid carbon dioxide slurry stream from a liquid purified primary component stream.

[0026] In some embodiments of systems for separating carbon dioxide from a process stream without condensing a primary component of the process stream, the systems comprise a desublimation heat exchanger configured to receive a process stream comprising gaseous carbon dioxide and a primary component, configured to receive a colder contact liquid stream, configured to directly contact the process stream with the colder contact liquid stream and cool the process stream to at or below the frost point of carbon dioxide in the process stream, configured to produce a gaseous purified primary component stream, and configured to produce a solids-containing contact liquid stream. The systems may further comprise a solid-liquid separator configured to receive the solids-containing contact liquid stream and physically separate a solid carbon dioxide slurry stream from a purified contact liquid stream.

[0027] The methods and systems disclosed herein may be used to remove carbon dioxide ("C0₂") and condensable or absorbable liquids from a process stream. For example, the methods and systems may be used for removing C0₂, natural gas liquids, and other components that condense and/or absorb under the specified operating conditions from a raw natural gas stream. In another example, the methods and systems may be used for treating syngas/producer gas stream for C0₂ and other condensable/absorbable components. In both cases, the process produces a treated stream with less C0₂ and condensable liquids. Additionally, a liquid CO₂ stream and a separated liquids stream may be produced as well.

[0028] The methods and systems may be used to treat both high-pressure streams, meaning streams at pressures and temperatures under which the bulk of the stream condenses to form a liquid in some portion of the process, and low-pressure streams, meaning streams at pressures and temperatures under which the bulk of the treated stream remains a gas but that may nevertheless be at greater than ambient pressure. Process descriptions for these two exemplary embodiments appear in separate descriptions below. [0029] LNG quality requirements are 2% and 2.5% C0₂ in Canada and the European Union, respectively (Grunvald, A., N. Izotov and V. Nemov (2008). Gas Quality Requirements as a Factor of Successful LNG Projects Implementation. International Gas Union Research Conference, Paris.). The United States does not currently have LNG quality requirements, but re-vaporized LNG must meet natural gas pipeline standards of 2-4% C0₂ (Gas Processors Suppliers Association (1998). (1998). GPSA Engineering Data Book. Tulsa, OK.). Even with these standards, in practice natural gas is pretreated for CO₂ removal down to 50 ppm before liquefaction. The reason for CO₂ removal down to 50 ppm stems from concerns with degradation of operability due to potential CO₂ freezing during natural gas liquefaction. The solubility of CO₂ in the final LNG product at normal conditions is higher than 50 ppm (Shen, T., T. Gao, W. Lin and A. Gu (2012). "Determination of CO2 Solubility in Saturated Liquid CH₄ + N₂ and CH₄ + C₂H₆ Mixtures above Atmospheric Pressure." Journal of Chemical & Engineering Data 57(8): 2296-2303.)

High Pressure

[0030] An exemplary process configuration for the condensing or high-pressure process appears in Figure 1 with major equipment described in Table 1. The discussion focuses on natural gas processing; however, the technology applies to any process in which a major portion of the stream to be treated condenses as a liquid (at the pressures of the stream and at a temperature higher than the frost point of CO₂ in the stream). The dashed, solid, and dot-dashed lines in the Figure represent streams that are primarily gaseous, liquid, and solid, respectively. Multiple phases may exist in many of the streams, with the type of line representing the dominant phase. Table 1 Major pieces of equipment in the natural gas treating loop. Equipment numbers correspond to Figure 1 .

Equipment Description

j E-37 Condensing heat exchanger I

j E-46 Natural gas liquids (NGL) separator I

! E-123 Natural gas liquids (NGL) pump

i E-38 Condensing heat exchanger II

; E-55 Natural gas liquids (NGL) separator II

j E-49 Condensing heat exchanger III

j V-1 Pressure regulating valve or turbine

j E-53 Solids-forming direct-contact heat exchanger

i E-41 Solids-liquids separator I

i V-3 Pressure regulating value of turbine

i E-50 Solids/slurry pump I

i E-51 Solids-liquids separator II

j E-40 Solids melter

j E-48 Liquid pump

[0031] Figure 1 includes three subprocesses, namely a natural gas treating loop, a melting loop, and a low-temperature cooling loop. Only the first of these is required to implement the reducing gas cryogenic carbon capture process, with the possible requirement of supplemental refrigeration of traditional types. Descriptions of all three exemplary subprocesses appear separately below. The main processes are removal of natural gas liquids and CO2 from the raw natural gas stream. These processes occur in the natural gas treating loop and are described first.

[0032] Natural Gas Treating Loop

[0033] The natural gas treating loop involves the major pieces of equipment identified in Table 1 and the associated connecting streams, minor equipment, and controls, listed in the order that the incoming raw natural gas stream encounters them. [0034] The exemplary process begins with raw natural gas (the "process stream" at the "first pressure" of this example). This gas cools to ambient or slightly below ambient temperature using cooling water or other resources (the "first temperature" of this example) and is then dried using conventional techniques that are not illustrated. The raw, dry natural gas feed stream first cools in heat exchanger E-37 (the "first heat exchanger" of this example) to temperatures above and near the melting point of pure C0₂ at the pressure of the system (the "second temperature" of this example), which in most cases will be near -55 °C. "Above and near" may comprise less than about 15° C above, less than about 10° C above, or less than about 5° C above. The first heat exchanger condenses some of the natural gas liquids present in the process stream as the stream cools. These natural gas liquids separate (the "first separated liquids stream" of this example) from the gaseous bulk of the flow in E-46 and combine with other natural gas liquid streams originating from other portions of the process to form stream P-191 . Stream P-191 returns counter-currently through the heat exchanger to return to near the first temperature as it helps cool the process stream. A liquid pump, E-123, included as part of E-46, raises the pressure of the stream P-189 such that it can mix with stream P-209 to form stream P-191 . Stream P-191 may be at sufficient pressure that none of it, or only the lightest components of it, will vaporize as it warms back to the first temperature in E-37. In other embodiments, some or all of the stream will vaporize.

[0035] In an alternative embodiment, the liquids collected in E-46 flow in a separate stream through E-38 and rejoin the vapors in stream P-215, with or without any liquids collected in E-55. In this alternative embodiment, any liquids condensed may be combined with the condensed primary component formed in E-49.

[0036] The bulk of the natural gas stream (the "process stream") flows as a gas from E-46 into a second heat exchanger, E-38, that drops the temperature to above and near the condensation point of the natural gas at the pressure of the system (the "third temperature" of this example), which is typically about -82 °C. Some trace impurities, such as Hg, will largely condense with the liquids in E-46 while others, such as H₂S, may not condense until later in the process, depending on their concentrations in the raw gas. Other trace components may never condense, such as noble gases like helium and argon. Additional natural gas liquids condense as the stream cools, and E- 55 separates these natural gas liquids (the "second separated liquids stream" of this example) from the gaseous stream and introduces them to the natural gas liquids stream P-197 in a manner similar to E-46, namely, by pumping them to the line pressure. They return through E-38 and help cool the incoming natural gas stream as they warm.

[0037] The bulk of the natural gas stream (the "process stream") leaves E-55 as a vapor and enters a third heat exchanger E-49, where the methane condenses to form some or mostly liquid as stream P-195. The now-liquid natural gas stream exits the heat exchanger E-49. Depending on the initial gas composition, it is possible that stream P-195 will contain CO2 or other gas-phase species. These are separated in stream P-345 (the "third separator" of this example) to join the solid CO2 stream at this point. Non-condensed trace components, such as noble gases, could also be separated at this point from stream P-345. Alternatively, non-condensed gases may be separated slightly later in the process in versions that do not have a melting loop, such as discussed below. The liquid natural gas (the "process stream") passes through a pressure regulating device shown as valve V-1 in the diagram but which could also be a cryogenic turbine.

[0038] The natural gas stream which is now line P-227 passes into a solids-forming heat exchanger (the "desublimation heat exchanger" of this example) E-53, similar to those disclosed in U.S. 8,715,401 or U.S. 8,764,885, or of other suitable type. The desublimation heat exchanger may be a direct-contact heat exchanger and configured to form solids in the heat exchanger without fouling or plugging and may integrate heat transfer to minimize both pressure drop and energy consumption. The heat exchanger forms solid C0₂ in the stream as the stream cools to its lowest temperature, which is dictated by the amount of C0₂ and natural gas liquids removal required by the process. Depending on the operating pressure and composition, some vapor or gases may be present in E-53, P-227, and possibly P-195. The solids-forming heat exchanger may be staged (e.g., one or more additional desublimation heat exchangers) to maximize the process efficiency.

[0039] The solid-liquid slurry, P-155, that forms in the solids-forming heat exchanger, E-53, flows into a solids-liquid separation device, E-41 . The solids leave the separator, E-41 , as a slurry in P-199, and combines with the residual light gases in stream P-345, if there are any. The slurry in P-199 may have as little residual liquid as possible - as much as is needed for transport via suitable auger, pump, or other conveyance, E-50, back through heat exchanger E-49. The slurry in P-199 helps cool the process stream as it warms. The liquids phase (the "liquid purified primary component stream" of this example), P-179, which contains most of the now-refined natural gas in a liquid phase, exits the solids-liquid separator, E-41 , and flows in line P-179 through a pressure control valve, V-3, and then as line P-217 back into heat exchanger, E-49, where it vaporizes and warms as it helps to cool the incoming stream. The pressure of the returning natural gas liquid stream, P-179, is regulated by valve V-3 or conceivably a turbine to form stream P-217 to optimize the performance of the system, specifically to provide optimal temperature profile matching in E-49.

[0040] The contacting liquid in the solids-forming heat exchanger forms from the condensates of the natural gas stream, which includes the methane in this example. It will typically be saturated with C0₂ by the time it exits the heat exchanger at its low- temperature limit. In the case that there is insufficient condensed methane to satisfy the demand for a contacting liquid, a portion of P-179 could be cooled and then recirculated to E-53 to maintain adequate liquid to operate the desublimation heat exchanger.

[0041] Returning to Figure 1 , the natural gas stream, P-197, exits E-49 as a gas with reduced natural gas liquids and CO2 contents, as well as reduced contents of other condensable gases and trace contaminants (H₂S, Hg), and flows through heat exchangers E-38 and E-37, cooling the incoming streams as it warms. The natural gas eventually returns to near the first temperature as a refined product. The solid CO2 stream, P-201 , exits E-49 after helping to cool the incoming process stream, P-215, and continues to warm as it cools the incoming gas process stream, P-185, in heat exchanger E-38. [0042] Alternatively, the liquefied natural gas, such as in P-179, may not be warmed and vaporized as illustrated, but instead may be transported to an LNG distribution network, with or without additional processing.

[0043] Returning to Figure 1 , the solid C0₂ stream exits heat exchanger E-38 near its melting point and flows to a solids-liquids separation device, E-51 . Routing the solids streams P-203 and P-201 through the heat exchangers E-49 and E-38 may not be practical, and the solids may go directly from E-41 to E-51 . The solids-liquids separator, E-51 , removes residual liquids from the stream and returns these to the natural gas liquids stream as stream P-207. The remaining solids flow as stream P-149 to the melting heat exchanger, E-40, where they melt as they condense stream P-159. Stream P-159 is described as part of the melting loop below.

[0044] The liquid C0₂ stream, P-145, exiting the melting heat exchanger, E-40, is further pressurized in pump E-48 and then flows through heat exchanger E-37 to help cool the incoming raw natural gas feed (the "process stream") as it returns to near the first temperature as a nearly pure, liquid CO2 stream. The final state of the CO2 depends on the incoming stream temperature and overall pressure. The state can be liquid, supercritical, or gas.

[0045] The process pressure after the expansion valve/turbine, V-1 , determines several operating conditions of the process. The example illustrated in Figure 1 assumes little to no pressure drop in V-1 . If the pressure drops sufficiently that methane forms some vapor, the methane in the system becomes an auto-refrigerant and can perform some or all of the cooling. [0046] If, in addition, the amount of C0₂ is low or the heat recovery from the C0₂ is unimportant, a simple version of the process as illustrated in Figure 2 may be used. This version of the process would usually be able to reduce C0₂ content to pipeline specifications (< 2%) and/or to LNG specifications (< 0.1 %). In this case, the solids separator, E-41 , produces a fluid stream that contains both gas and liquid, P-179, but the remainder of the process is similar to that of Figure 1 . The process may need supplemental cooling at certain locations, as would be provided by refrigeration loops commonly known to process engineers.

[0047] If maintaining pressure is important or the pressure drop in V-1 is insufficient for a portion of the stream to vaporize, solid C0₂ formation will require additional cooling. Some non-limiting examples of possible cooling mechanisms are discussed in the next section.

[0048] Depending on the composition of the raw natural gas (the "process stream") and the relative importance of operating costs, energy efficiency, and capital costs, the steps described in both of the embodiments above may suffice to perform the separations, possibly augmented by refrigerant loops to supplement cooling where needed. The process diagram in Figure 1 illustrates additional innovations that increase energy efficiency and decrease overall complexity and cost, as discussed next.

[0049] Some optional cooling support for the melting heat exchanger, E-40, and the solids-forming heat exchanger, E-53, are discussed below.

[0050] The Melting Loop

[0051] The melting loop uses a nearly closed-loop refrigeration system to melt the solid C0₂ and transfer the heat to the coldest point in the overall system. It involves the major pieces of equipment identified in Table 2 and the associated connecting streams and controls.

Table 2 Major components of the melting loop. Equipment numbers correspond to

Figure 1 .

Equipment Description

; E-43 Compressor (preferably with inter-stage coolers) j E-44 Ambient heat exchanger (or inter-stage coolers in E-43) i j E-39 Recuperating heat exchanger I

j E-40 Solids melter

! E-42 Recuperating heat exchanger II

i E-47 Expansion valve or turbine

; E-76 Low-temperature heat exchanger

[0052] The cooling loop compresses the refrigerant in compressor E-43 and cools it in a heat exchanger E-44 to or near the available heat rejection temperature of the process, which will usually be near ambient temperature. Many embodiments may use staged compressors and heat exchangers to maximize the efficiency of this process, effectively combining E-43 and E-44 in several stages in a single unit. The pressurized refrigerant in P-175 cools to near the melting point of CO2 in heat exchanger E-39 and then flows through P-159 and condenses in the melting heat exchanger, E-40, as it melts the solid CO2. The resulting liquid refrigerant stream, P-165, flows through a second recuperating heat exchanger, E-42, to cool to as low of a temperature as possible as it warms the refrigerant flowing counter-currently in the same heat exchanger. The cool refrigerant stream, P-169, enters an expansion valve or expansion turbine, E-47, where the pressure drops. The resulting stream vaporizes in E-76 and warms as it cools stream P-331 that comes from the solids-forming heat exchanger. The gaseous refrigerant stream, P-163, returns through both recuperating heat exchangers, E-42 and E-39, as it warms back to near ambient temperatures, at which point it completes the loop.

[0053] The primary purpose of this loop is to shift the heat of melting C0₂ from its nominal melting point, -55 °C, to a temperature low enough to provide cooling for the solids-forming heat exchanger. This could be enough energy to freeze all of the C0₂ in the solids-forming heat exchanger. However, if process conditions and heat losses require additional cooling, a supplementary cooling loop of similar design but without the melting heat exchanger and using either a reverse Brayton or reverse Rankine cycle with recuperative heat recover would supplement this loop. Such cooling loops are well known to one skilled in the art of such processes.

[0054] The Low-Temperature-Heat-Exchange Loop

[0055] The low-temperature-heat-exchange loop supplements any auto-refrigerant cooling done by dropping the pressure in V-1 and uses a nearly closed-loop refrigeration system to form solids in direct-contact heat exchanger, E-53. It involves the major pieces of equipment identified in Table 3 and the associated connecting streams and controls.

Table 3 Major components of the low-temperature-heat-exchange loop.

Equipment numbers correspond to Figure 1.

- an pressure r v ng orce

[0056] A light gas minimally soluble in the liquid natural gas (the "process stream") in the solids-forming heat exchanger, E-53, cools in the low-temperature heat exchanger,

E-76, to as low of a temperature as P-187 reasonably allows. This cold gas passes by the liquid natural gas either as a bubbling stream or in a cryogenic spray tower configuration in E-53. The gas warms as it cools the liquid stream coming from P-227, solidifying C0₂ as the liquid/slurry temperature drops. A fan or other suitable pressurizer provides the pressure rise required for the gas with small amounts of natural gas vapor to return to the low-temperature heat exchanger, E-76. Gases of potential interest include N₂, any noble gas, CO, and any other suitable material. A small amount of this gas will inevitably be entrained by or dissolve in the stream flowing from the solids-forming heat exchanger, P-155. This will have to be made up over time by some gas supply. Air is a potential candidate for the gas, as the stream P-155 and all subsequent natural-gas-containing streams should be well above the higher flammability limit and P-325 and all other cooling streams should be well below the lower flammability limit. The circulating gas in P-323, P-325, and P-331 should saturate with both methane and CO₂ and will neither remove nor add either material from the process, under steady-state conditions, once the initial transient is over.

Low Pressure

[0057] A similar exemplary process to that illustrated in Figures 1 and 2 and that operates at pressures too low or temperatures too high to condense the primary component (natural gas, syngas (CO and H₂), or any other light gas mixture in which the major product does not condense at the temperature and pressure of operation) appears in Figure 3. It is similar to the condensing process described above. The melting loop is essentially identical. The major components of the process appear in Table 4. This process is described in terms of its subprocesses similar to above. As with the high-pressure, condensing system, this process begins by conditioning the gas (the "process stream" of this example) to as low of a temperature as is locally achievable using local cooling water or air and condensing heat exchangers (the "first temperature" and the "first pressure" of this example). Any moisture in the process stream is also removed using absorbents or other available equipment. [0058] If the level of C0₂ solids formation requires more cooling than is available from this stream, a supplemental refrigerant loop could be incorporated into this low- temperature loop.

[0059] The Gas Treatment Loop

Table 4 Major pieces of equipment in the noncondensing system. Equipment numbers correspond to Figure 3.

Equipment Description

E-116 Heat exchanger

i E-120 Liquids separation

; E-121 Heat exchanger II

; E-107 Desublimating heat exchanger

j E-106 Solids-liquids separation

j V-9 Pressure reduction valve/turbine

j E-122 Solids/slurry pump I

! E-108 Heat exchanger III

i E-109 Solids-liquids separator II

; E-118 Solids melter

! E-114 Liquid pump

[0060] The process begins with raw gas (the "process stream" at the "first pressure" of this example). This gas cools to ambient or slightly below ambient temperature (the "first temperature" of this example) using cooling water or other resources and is then dried using conventional techniques that are not illustrated. The raw, dry gas feed stream first cools in the first heat exchanger E-1 16 to temperatures near the melting point of pure CO2 at the pressure of the system (the "second temperature" of this example), which in most cases will be near -55 °C. The first heat exchanger condenses vapors such as natural gas liquids, if present, as the stream cools. These liquids separate (the "first separated liquid stream" of this example) from the gaseous bulk of the flow in E-120 and combine with other liquids streams originating from other portions of the process to form stream P-439, which returns counter-currently through the heat exchanger to return to near the stream initial temperature as it helps cool the incoming process stream. A liquid pump, included as part of E-120, raises the pressure of the stream P-507 such that it can mix with stream P-503 to form stream P-439. The liquid stream may be at sufficient pressure that none of it, or only the lightest components of it, will vaporize as it warms back to its initial temperature. In other examples, some or all of the stream may vaporize.

[0061] The bulk of the gas stream (the "process stream") flows as a gas from E-

120 into a second heat exchanger, E-121 , that drops the temperature to above and near the frost point (the "third temperature" of this example, i.e., the temperature at which solid CO2 begins to form in the stream). Some trace impurities, such as Hg, will largely condense with the liquids in E-1 16 while others, such as H₂S, may not condense until later in the process, depending on their concentrations in the raw gas.

Some constituents, such as H₂, NO, and CO, will not condense at any stage of this process and are considered light gaseous products produced with the processed gaseous products. Additional vapors may condense as the stream cools, in which case stream P-51 1 enters the desublimating heat exchanger, E-107, as a two-phase (gas, liquid) system.

[0062] The desublimating heat exchanger may be one disclosed in U.S. 8,715,401 or U.S. 8,764,885. The desublimation heat exchanger may be a direct- contact heat exchanger and configured to form solids in the heat exchanger without fouling or plugging and may integrate heat transfer to minimize both pressure drop and energy consumption. The gases in stream P-51 1 (the "process stream") flow counter-currently with colder liquids introduced into the vessel as stream P-443, and solid CO2 forms on the liquid surface as the streams pass, removing CO2 from the gaseous stream. The slurry that results flows through P-467 into a solid-liquid separator, E-106. The separator forms a high-solids-loading slurry with the solids which exits in P-505, and a liquid phase (the "purified contact liquid stream" of this example) which exits in P-527. This liquid phase includes the liquids introduced into the desublimating heat exchanger in P-443 and those that condensed and entered through P-51 1 . A portion of this liquid stream splits off as P-531 and the remainder flows back through the heat exchangers as P-533 (the "separated contact liquid stream" of this example). The split portion P-531 passes through a valve or turbine, V-9, to decrease the pressure and reduce the tendency of solids to form as it cools in a heat exchanger (part of the "first refrigeration system" of this example) that drops the slip stream to the lowest temperature of the system, E-108. This stream returns to the desublimating heat exchanger, E-107, and completes the loop from which it started. Gases ( the "process stream") that contain no condensable vapors, such as many syngases and flue gases, return all of the liquids (the "contact liquid") back to the desublimating heat exchanger, E-107.

[0063] As an alternative to the processes involved in P-531 and V-9, the low- temperature loop can use any traditional external refrigerant cooling system if the CO2 content of the condensed phase is low enough. Figure 4 illustrates one method to lower the dissolved CO2 content. The CO2 slurry from the desublimating heat exchanger (bubbler or spray tower, P-467) passes through a solid-liquid separator as usual (E-106), producing one stream comprising primarily CO2 solid and a second liquid stream. The liquid stream comprises primarily the contacting liquid with some dissolved CO2. The liquid stream enters a low-pressure gas separation unit (part of the "desaturation system" of this example) in which the pressure is low enough that some dissolved CO2 changes phase. This decreases the dissolved CO2 content and changes the liquid temperature. Some of the dissolved CO2 and the remaining liquid are now in separate phases and return to their original pressures, such as via pumps, in separate streams. The CO2 stream will commonly form a solid in this process, and this stream combines with the previously formed solids stream. The liquid stream that is no longer saturated in CO2 (the "further purified contact liquid stream" of this example) enters a traditional heat exchanger where it cools without risk of solid CO2 formation.

[0064] The Melting Loop

[0065] The melting loop uses a nearly closed-loop refrigeration system to melt the solid CO2 and transfer the heat to the coldest point in the overall system. It involves the major pieces of equipment identified in Table 5 and the associated connecting streams and controls. Table 5 Major components of the melting loop. Equipment

correspond to Figure 3.

- ow- empera ure ea exc anger

[0066] The cooling loop compresses the refrigerant in compressor E-1 19 and cools it in a heat exchanger, E-1 13, to or near the available heat rejection temperature of the process, which will usually be near ambient temperature. Many embodiments will use staged compressors and heat exchangers to maximize the efficiency of this process, effectively combining E-1 19 and E-1 13 in several stages in a single unit. The pressurized refrigerant in P-479 cools to near the melting point of C0₂ in heat exchanger E-105 and then flows through P-459 and condenses in the melting heat exchanger, E-1 18, as it melts the solid CO2 in the gas treatment loop. The resulting liquid refrigerant stream, P-513, flows through a second recuperating heat exchanger, E-1 17, to cool to as low of a temperature as possible as it warms the refrigerant flowing counter-currently in the same heat exchanger. The cool refrigerant stream, P-475, enters an expansion valve or expansion turbine, E-1 1 1 , where the pressure drops. The resulting stream vaporizes in E-108 and warms as it cools the liquid stream P-451 (the "purified contact liquid stream") that comes from the solids-forming heat exchanger. The gaseous refrigerant stream, P-509, returns through both recuperating heat exchangers, E-1 17 and E-105, as it warms back to near ambient temperatures, at which point it completes the loop. [0067] The primary purpose of this loop is to shift the heat of melting CO2 from its nominal melting point, -55 °C, to a temperature low enough to provide cooling for the solids-forming heat exchanger. This could be enough energy to freeze all of the CO2 in the solids-forming heat exchanger. However, if process conditions and heat losses require additional cooling, a supplementary cooling loop of similar design but without the melting heat exchanger and using either a reverse Brayton or reverse Rankine cycle with recuperative heat recover would supplement this loop. Such cooling loops are well known to one skilled in the art of such processes.

[0068] Cooling Loops

[0069] Any of the processes disclosed herein may require additional cooling loops as are common in this industry to overcome heat losses, to balance heat loads, or to otherwise maintain efficient and effective temperature profiles throughout the system.

[0070] Subprocesses

[0071] One of ordinary skill in the art, having the benefit of this disclosure, would understand that a number of variations could be made to the processes of Figures 1 through 4. Additionally, only a portion of the processes illustrated in Figures 1 through 4 may be implemented. For example, portions of the above processes can retrofit existing natural gas and syngas systems without building the entire process illustrated in the figures. Specifically, using the desublimation heat exchangers and the surrounding equipment can retrofit existing natural gas processes, such as amine processes. In another example, when the primary component is natural gas, a portion of the condensed natural gas formed in some of these processes can be used as liquefied natural gas (LNG) product, which will reduce the amount of material circulating back through the system and change the amount and location of supplemental refrigeration required. Subprocess implementations could be among the first implementations of the embodiments disclosed herein in commercial practice.

[0072] In regard to the temperature calculations discussed herein, the high- pressure methods and systems pertain to conditions at which the primary component of the gas condenses at the pressure of the system. Since the gas process streams generally are mixtures, this condensation occurs over a temperature range rather than at a specific temperature as occurs for pure components. Standard theoretical techniques or experimental measurements may be used to determine these temperatures. The predictive techniques in general may include non-ideal equations of state (Peng-Robinson, Soave-Redlich-Kwong, and Predictive Soave-Redlich- Kwong are common examples). Additionally, activity coefficient models (NRTL, Wilson, Uniquac, and Unifac are common examples) may also be used and possibly a Poynting correction. Many of these equations require or would benefit from experimentally determined interaction parameters. In general, the process removes moisture, cools to the point of the major phase beginning to condense, during which cooling minor components such as natural gas liquids substantially condense, cool further as the major component condenses, and cools further in a desublimation heat exchanger as C02 condenses and usually at least partially forms a solid. These condensation points can all be measured experimentally or predicted as previously indicated.

[0073] In the low-pressure process, the gases cool to near the temperature at which CO2 begins to desublimate. During this cooling, minor components often condense from the gas. These components can be either separated from the stream and returned, as illustrated, or combined with the separated stream if this is beneficial. Further cooling forms condensed CO2. Desublimation heat exchangers provide the mechanism for cooling as solid CO2 (or any other component) forms. These condensation points can all be measured experimentally or predicted as previously indicated.

[0074] Although not limited to such, the foregoing cryogenic purifying methods and systems may be used to remove carbon dioxide from raw natural gas that has been dried or comes sufficiently dry from the wellhead. Removal of acid gases, such as carbon dioxide, is often an early stage in natural gas processing. Extractive distillation methods and systems are also disclosed herein that may be used in later stages of natural gas processing. Conventionally, one of the final natural gas processing steps is the separation of natural gas liquids (NGL) from the gas. This is generally done with a demethanizer distillation column that separates methane gas from the NGL. Possible NGL that may be present in raw natural gas include ethane, propane, butane, pentane, and heavier hydrocarbons. Conventionally, the NGL are separated into individual components via additional distillation columns, and each component is further purified. All natural gas constituents absorb CO2 to some degree when in the liquid phase. The existence of a minimum-temperature azeotrope between ethane and carbon dioxide particularly complicates CO2 separation from ethane.

[0075] Figure 5 illustrates a direct sequence of extractive distillation columns (a variation of the conventional scheme) used to separate CO2 from ethane, and is based on the information provided by Luyben and Tavan et al. [2], [4]. Figure 6 displays the temperature and liquid composition profiles for this base case. CO2 collects as the top distillate from the first distillation column (extraction column), while the bottom product - consisting of ethane and heavier hydrocarbons (C3+) and substantially free of CO2 - feeds the second distillation column (solvent recovery column). High-purity ethane is obtained as the distillate product, and heavier hydrocarbons (NGL) are obtained as the bottom product of the solvent recovery column. The recovered NGL is divided into two parts, one of which is pumped back into the first column for breaking the azeotrope, and the second part goes to a sequence of conventional distillation columns (not shown) for separation into C3, iC₄, nC₄, 1C5, and nCs product streams.

[0076] "Substantially free" as used herein means free of less than 3% of the stated compound, but can include less than 2% and less than 1 % of the stated compound on a mole percent basis.

[0077] In contrast to the scheme of Figure 5, in some embodiments of methods of separating carbon dioxide from ethane contemplated herein, the methods comprise providing a feed stream comprising carbon dioxide, ethane, and higher molecular weight hydrocarbons and introducing the feed stream into a first distillation column, wherein the first distillation column is sized and configured to provide a first distillate stream and a first bottoms stream, wherein the first distillate stream comprises substantially pure carbon dioxide. The methods may further comprise introducing at least a portion of the first bottoms stream into a second distillation column, wherein the second distillation column is sized and configured to provide a second distillate stream and a second bottoms stream, wherein the second bottoms stream comprises higher molecular weight hydrocarbons and is substantially free of carbon dioxide and ethane. The methods may further comprise introducing at least a portion of the second bottoms stream into the first distillation column as a solvent stream, separate from the feed stream. The methods may further comprise introducing at least a portion of the second distillate stream into a third distillation column, wherein the third distillation column is sized and configured to provide a third distillate stream and a third bottoms stream, wherein the third bottoms stream comprises ethane and is substantially free of carbon dioxide and higher molecular weight hydrocarbons. The methods may further comprise combining at least a portion of the third distillate stream into the first distillation column separate from the feed stream.

[0078] The higher molecular weight hydrocarbons may include propane, butane, pentane, any natural gas component less volatile than ethane, or combinations thereof.

[0079] The first distillate stream may comprise at least about 90% pure, about 91 % pure, about 92% pure, about 93% pure, about 94% pure, or about 95% pure carbon dioxide. Additionally or alternatively, the first distillate stream may be condensed and at least a portion refluxed to the first distillation column. The carbon dioxide may be stored for reinjection into the ground or used in other ways.

[0080] The first bottoms stream may comprise a significant amount of carbon dioxide impurity, for example, about 3 wt% or more, about 4 wt% or more, about 5 wt% or more, about 6 wt% or more, about 7 wt% or more, about 8 wt% or more, about 9 wt% or more, or about 10 wt% or more. This is in contrast to conventional extractive distillation schemes, wherein the bottom stream of the first distillation column is substantially free of CO2, such as in the Figure 5 scheme where the CO2 is about 0.05 wt% in that stream. Under conventional schemes, the first distillation column is sized and configured to achieve complete CO2 separation in the first column. It has been discovered that by adding a third distillation column and instead of focusing on complete CO2 separation, recycling an azeotropic mixture of CO2 and ethane from the third distillation column, surprisingly, capital costs and operating costs can be reduced, as compared to the two-column scheme of Figure 5.

[0081] In keeping with the foregoing, the second distillate stream may comprise ethane and a significant amount of carbon dioxide impurity, such as, for example, about 3 wt% or more, about 4 wt% or more, about 5 wt% or more, about 6 wt% or more, about 7 wt% or more, about 8 wt% or more, about 9 wt% or more, or about 10 wt% or more. The second distillate stream may be partially condensed and refluxed to the second distillation column and the uncondensed portion introduced to the third distillation column.

[0082] The third distillate stream will generally comprise a substantial amount of ethane and a substantial amount of carbon dioxide, such as an azeotropic mixture of the two. The third distillate stream may be partially condensed and refluxed to the third distillation column and the uncondensed portion is the portion combined with the feed stream.

[0083] As should be understood, the feed stream may comprise the bottoms stream from a demethanizer column (not illustrated). One of ordinary skill in the art, with the benefit of this disclosure, would understand how to optimize the ratio of the second bottoms stream (solvent stream) to the feed stream so as to optimize the process. The portion of the second bottoms stream not combined with the feed stream may be further processed using conventional processes. For example, the portion of the second bottoms stream not used as solvent may be sent to a depropanizer column for separating out propane. The bottoms from the depropanizer column may be sent to a debutanizer column for separating out butane and so forth for separating out pentane. [0084] One of ordinary skill in the art would understand, with the benefit of the present disclosure, how to size the distillation columns, select the number of trays, and select feed locations for the various streams, so as to achieve optimal performance.

[0085] In some embodiments, heat may be exchanged between the second bottoms stream and the third bottoms stream and/or the third distillate stream prior to introducing a portion of the second bottoms stream as a solvent.

[0086] In some embodiments, such as in the illustrated embodiments, heat is not exchanged between the first distillate stream and the second bottoms stream, thereby allowing the CO₂ in the first distillate stream to remain in the liquid phase. The methods of separating carbon dioxide from ethane contemplated herein may also be used with a new installation or with an existing extractive distillation process that has been retrofitted. Accordingly, methods of retrofitting are contemplated herein. In some embodiments, methods of retrofitting an existing extractive distillation process, such as that disclosed in Figure 5, comprise: reconfiguring the first distillation column to provide a first bottoms stream comprising a significant amount of carbon dioxide impurity; introducing at least a portion of a second bottoms stream of the second distillation column as a solvent stream to the first distillation column, separate from the feed stream; and adding a third distillation column and introducing at least a portion of a second distillate stream of the second distillation column into the third distillation column, wherein the third distillation column is sized and configured to provide a third distillate stream and a third bottoms stream, wherein the third bottoms stream comprises ethane and is substantially free of carbon dioxide and higher molecular weight hydrocarbons. [0087] The retrofit methods may further comprise combining at least a portion of the third distillate stream with the feed stream prior to introducing it to the first distillation column. The third distillate stream may be partially condensed and refluxed to the third distillation column and the uncondensed portion combined with the feed stream. The third distillate stream may comprise an azeotropic mixture of ethane and carbon dioxide.

[0088] In some embodiments, an extractive distillation system for separating ethane from carbon dioxide comprises a first distillation column configured to receive a feed stream and a separate recycle stream. The first distillation column is sized and configured to provide a first distillate stream and a first bottoms stream. The system further comprises a second distillation column configured to receive the first bottoms stream, wherein the second distillation column is sized and configured to provide a second distillate stream and a second bottoms stream. The system may include a diversion system configured to provide a portion of the second bottoms stream as the recycle stream. The system further includes a third distillation column configured to receive the second distillate stream, wherein the third distillation column is sized and configured to provide a third distillate stream and a third bottoms stream, wherein the third distillate stream is combined with the feed stream.

[0089] Depending on the composition of the feed stream, the feed stream may be introduced within the lower 15% of the first distillation column. Likewise, depending on the composition of the feed stream, the recycle stream may be introduced within an upper 15% of the first distillation column and may be substantially condensed. The first bottoms stream may in turn be introduced to the second distillation column within 15% of the middle of the second distillation column. The second distillate stream may be introduced to the third distillation column in an upper portion of the third distillation column and may be substantially uncondensed.

[0090] Figure 7 illustrates an exemplary system and method for separating carbon dioxide and ethane, as discussed above. The exemplary system involves three columns: the CO2 recovery or extraction column ("first distillation column"), the solvent recovery column ("second distillation column"), and the concentrator column ("third distillation column"). In this process, not all the CO2 exits the top of the extraction column, the first column. In this example, the bottom product of the extraction column contains 10 mol % CO2 along with ethane and heavier hydrocarbons. The second column recovers high-purity solvent. The recovery column distillate feeds the concentrator column, which produces ethane as a product and an azeotropic mixture recycle stream.

[0091] The exemplary extractive column had 39 stages and operated at 24 atm.

The feed gas entered on tray 36 and the solvent with the flow rate of 2.4 kmol/s

(Solvent/Feed = 0.6) entered on tray 5 near the top. Figures 8(a) and (b) plot the temperature and liquid composition profiles in the extractive column, respectively.

The solvent in the extractive distillation column ("first distillation column") altered the relative volatility between CO2 and ethane, driving CO2 to the top of the column and ethane to the bottom of the column. The upper section of the first column (above the entrainer (i.e., solvent) feed location) separated the CO2 and the entrainer. Figure

8(b) indicates that the CO2 concentration increased at the entrainer entry point

(stage 5). The middle of the column, between the entrainer feed stage and the fresh feed stage, prevented ethane from going up the column. Figure 8(b) clearly shows that the concentration of ethane increased from stages 5 to 36, where the entrainer and the feed enter, respectively. The bottom of the column, below the fresh feed location, prevented CO2 from going down the column. The extractive column produces a C02-rich distillate (95.6 mol %).

[0092] Figure 9 illustrates the effects of changing the solvent flow rate (s) and/or reflux ratio ( S). Increasing the reflux ratio decreased the impurity of solvent in the distillate, while increasing the solvent flow rate improved the distillate CO2 purity. However, the same is not true for the C02-ethane system when using the NGL solvent. The effect of higher solvent flow rates depended on the reflux ratio; in the higher RR range, increasing the solvent flow rate also increased the distillate CO2 purity (Figure 9(a)). However, in the lower RR range, the opposite occurred.

[0093] Additionally, Figures 9(b) and (c) reveal nonmonotonic relationships between RR and both of the distillate impurities (C2 and C3), but they were opposite in shape. The C2 curve reaches a minimum and the C3 curve (the lightest of the components in the NGL solvent) reaches a maximum. The same relationships are also true of the solvent flow rate: more solvent decreased C2 impurity but increased C3 impurity.

[0094] These interesting phenomena occurred because the solvent is chemically similar to the ethane being separated from the CO2. While operated at the lower of the two possible reflux ratios, the minimum solvent flow rate was found which met the two specifications for the extractive column. As shown in Figure 7, the solvent flow rate was 2.4 kmol/s and the reflux ratio was 4.61 . The resulting heat exchanger duties were 87.86 MW in the condenser and 15.12 MW in the reboiler. The distillate flow rate was 1 .347 kmol/s of mostly C0₂ (95.6 mol %) with impurities of 2.9 mol % ethane and 1 .4 mol % propane. The bottoms flow rate of the column was 6.4 kmol/s and carried most of the ethane, some of the C0₂ in the fresh feed, and heavier hydrocarbons to the solvent recovery column ("second distillation column"). [0095] The distillate of the extractive column in this design remains liquid. In contrast, the distillate of the conventional design cools the recycled NGL, which converts it to a vapor stream. There are several potential heat integration steps for this liquid stream, depending on the potential use of the CO2. For example, a simple pump could pressurize the stream to above its vapor pressure at ambient conditions. The stream could then warm to ambient temperature by heat integration with any one or several of the condensers, further decreasing the process energy demand. The final liquid stream would then be suitable for enhanced oil recovery or other pipeline-based, large-scale CO2 applications. Alternatively, if the CO2 was to be locally vented, the stream could reduce the overall process energy demand significantly by heat integration with one or more of the condenser circuits.

[0096] The solvent recovery column ("second distillation column") had 37 stages, and the first bottoms stream of the extractive column (first column) was fed on tray 15. Unlike the conventional design that uses a total condenser, this column in this exemplary design had a partial condenser. The design specifications of this column were 0.3 mol % propane in the distillate and 0.05 mol % ethane in the bottoms. A reflux ratio of 1 .08 was used to achieve these specifications.

[0097] Figures 8(a) and (c) exhibit the temperature and liquid composition profiles in the solvent recovery column, respectively. The ethane and CO2 concentrations functionally monotonically decreased from the distillate to the bottoms, but the C3 profile had two local maxima, one each between the feed and the distillate and the feed and the bottoms, with overall increasing concentration from the distillate to the bottoms.

[0098] The condenser duty was 37.1 MW, and the reboiler duty was 20.9 MW.

The heavy hydrocarbons exited with the bottoms product ("second bottoms stream") and split, via a diversion system, into the NGL product (0.834 kmol/s) and the solvent, which recycles back to the extractive column separate from the feed stream. As discussed previously, the NGL stream could pass through a sequence of traditional distillation columns for propane, butane, and pentane recoveries, which were not included in any of these simulations. The distillate of the solvent recovery column was a mixture of CO₂ (20 mol %) and ethane (80 mol %) that needed to be concentrated before recycling to the initial feed.

[0099] The concentrator column ("third distillation column") had 43 stages, and the distillate of the recovery column was fed on tray 10. This column also had a partial condenser. Ethane with high purity (99.7 mol %) formed the bottoms product (1.82 kmol/s) after heat recovery. The mixture of C0₂-ethane went overhead with a molar flow rate of 1 .35 kmol/s with the CO₂ concentrated up to 46 mol %. After heat recovery, this was recycled back to the extraction column as part of the feed stream.

[00100] To establish a fair comparison between the Figure 5 process and the exemplary Figure 7 process, the sequential quadratic programming (SQP) method was used to optimize both designs. The SQP optimization method coupled with the efficient sensitivity analysis tool from Aspen Plus minimized the total energy requirement for the extractive column, as follows:

where the optimization parameters used here are: the total number of stages (¾,)_> feed location (N_F), solvent location (¾), reflux ratio {BS), boilup rate (V), and solvent to feed flow rate ratio while and %^ are the vectors of the obtained and desired purities for the m products, respectively. An additional objective function determined the optimal energy cost vs. the number of stages [5]-[7]. [00101] The total capital costs, total operating costs, and total annual costs (TAC) were calculated. TAC was calculated as

&tt c&si (2) TAC = s &mtta? e&s - — — ;

where a plant life of 30 years was considered in this investigation. This somewhat exceeds many natural gas process plant lifetimes but also allows for equipment reuse. Most of the savings in the Figure 7 process were in operating costs, so the economics are relatively insensitive to the plant cost. The Aspen Process Economic Analyzer provides relative costs, taking into account capital and operating costs together with technical and process parameters. Table 6 compares certain economic performance indicators of the two processes. The introduction of the third column caused a noticeable decrease in the reflux ratios of the extractive and recovery columns, which was 4.61 and 1 .08, respectively, compared with 6.04 and 2.18 in the Figure 5 system. The capital costs of the columns were significantly altered by the reflux ratios, recycle flow rates, and entrainer usage in the distillation cases. Additionally, these parameters determined the process heat duties and product quality. As a result, the Figure 7 process leads to 10% lower TAC, with a 14% reduction in specific energy demand and CO2 emissions. All costs indicated here decrease. Total capital costs and most operating costs decrease by about 5%, with a 10% reduction in steam costs, consistent with the sum of the reboiler thermal loads being the biggest change.

[00102] The energy requirements closely correlate with CO2 emissions when no heat integration is considered. When part of the process heat is reused instead of primary energy, then the CO2 emissions are lower as compared to the figure expected from the energy data [1 ],[3]. Fuel combustion calculations assumed that air was in excess, which ensures complete combustion and prevents formation of carbon monoxide. The amount of CO2 emitted was related to the amount of fuel burned in the heating devices, and was calculated according to the method described by Gadalla et al. and Kiss et al. [8], [9]:

where = 3.67 is the ratio of molar masses of CO2 and C, and NMV is the net (lower) heating value of natural gas with a carbon mass fraction of 0.41 . Hence the quantity of fuel used was calculated as follows:

_ ¾ ¾g~¾ (4) where (kJ/kg) and (kJ/kg) are the latent heat and enthalpy of the steam, and T#?B (K) and _s (K) are the flame and stack temperatures, respectively. This equation represents a steam balance around the boiler and relates the quantity of fuel necessary to provide a heat duty of The hourly rate of CO2 emissions for the Figure 5 process and the Figure 7 process also appear in Table 6. This indicates that the exemplary process and system decreases the carbon footprint for extractive distillation of ethane and carbon dioxide.

Table 6

Performance indicators Figure 5 process Figure 7 process

Capital Costs

Extractive Recovery Extractive Recovery Concentrator column column column column column

Tower (USD) 8, 164,700 10,589,600 4,556,700 10,939, 100 2,502,700

Reboiler (USD) 301,400 549,600 62,100 693,100 69,600

Condenser (USD) 2,928,600 1,125,500 2,217,800 805,400 1,026,900

Reflux pump (USD) 125,300 68,300 104,500 46,300 46,200

Heat exchanger (USD) 988,000 599,700

External Cooler (USD) 56,300 -

Total capital costs (USD) 24,897,300 23,670, 100

Operating Costs

Electricity (USD/year) 516,657 491,334

Refrigerant (USD/year) 5,986, 169 5,632,501

[00103] As compared to the Figure 5 process, the exemplary process strategy showed an approximately 14% reduction in total energy demand and associated carbon emissions, most of which were from reduced steam demand. Aspen Plus process economics analyses indicated about a 5% reduction in capital and a 10% reduction in operating costs when comparing optimized versions of the Figure 5 process and the Figure 7 process. The Figure 7 process reduced the total annual costs (TAC) by 10%, without compromising the desired purification. The Figure 7 process was also easier to operate because it was unnecessary to withdraw CO2 completely in the extractive column. Additionally, the Figure 7 process produced C0₂ as a liquid product, which avoided the significant amount of energy required for liquefaction.

[00104] As discussed above, methods of cryogenically purifying process streams may be used to remove C0₂ from raw natural gas. Likewise, methods of separating carbon dioxide from ethane may be used in purifying the ethane separated from natural gas. Accordingly, methods are contemplated herein that encompass both processes. For example, a method of separating carbon dioxide from a process stream may comprise providing a process stream comprising gaseous carbon dioxide and further comprising a primary component and at least a secondary component. The method may further comprise cooling the process stream to at or below the frost point of carbon dioxide in the process stream, thereby forming solid carbon dioxide and then physically separating solid carbon dioxide from the process stream to form a separated solid carbon dioxide slurry stream and a liquid primary component stream. The method may further comprise separating at least the secondary component and residual carbon dioxide from the liquid primary component stream. The method may further comprise separating the residual carbon dioxide from the secondary component using extractive distillation with a concentrator distillation column. In the natural gas process setting, the primary component may be methane and the secondary component may be ethane. This example of combined processes may include any of the features of the separate cryogenic and extractive distillation processes disclosed in more detail above.

[00105] It should be understood that just as the cryogenic processes may be applied to non-natural gas process streams, likewise, the extractive distillation processes may be applied to streams comprising ethane and CO₂ that originate from sources other than natural gas. For example, if a process stream comprising ethane and CO₂ did not also contain higher molecular weight hydrocarbons that could be used as a solvent, the extractive distillation process could still be used. A solvent such as butane could be introduced and completely recycled through the process, instead of using naturally present higher molecular weight hydrocarbons.

[00106] Without further elaboration, it is believed that one skilled in the art can use the preceding description to utilize the present disclosure to its fullest extent. The examples and embodiments disclosed herein are to be construed as merely illustrative and exemplary and not a limitation of the scope of the present disclosure in any way. It will be apparent to those having skill in the art, and having the benefit of this disclosure, that changes may be made to the details of the above-described embodiments without departing from the underlying principles of the disclosure herein.

List of References Cited (the contents of which are incorporated herein by reference)

[1]Y. Tavan, S. Shahhosseini, S.H. Hosseini, Feed-splitting technique in the extractive distillation of C02- ethane azeotropic process, Separation and Purification Technology, 122 (2014) 47-53.

[2]Y. Tavan, S.H. Hosseini, A novel application of reactive absorption to break the C02-ethane azeotrope with low energy requirement, Energy Conversion and Management, 75 (2013) 407-417.

hematical modeling, Journal of Natural Gas Science and Engineering, 21 (2014) 275-282.

[3] A.A. Kiss, R.M. Ignat, Innovative single step bioethanol dehydration in an extractive dividing-wall column,

Separation and Purification Technology, 98 (2012) 290-297.

[4]W.L. Luyben, Control of an Extractive Distillation System for the Separation of C02 and Ethane in Enhanced Oil Recovery Processes, Industrial & Engineering Chemistry Research, 52 (2013) 10780-10787.

[5]I. Dejanovic, L. Matijasevic, Z. Olujic, An Effective Method for Establishing the Stage and Reflux Requirement of Three-product Dividing Wall Columns, Chemical and Biochemical Engineering Quarterly, 25 (2011) 147-157.

[6] A. Kiss, R. Ignat, Optimal economic design of a bioethanol dehydration process by extractive distillation, Energy Technol, 1 (2013) 166-170.

[7]Jordi Bonet-Ruiz, Alexandra-Elena Bonet-Ruiz, Victor-Corneliu Radu, Joan Llorens Llacuna, Jose Costa Lopez, A Simplified Cost Function for Distillation Systems Evaluation, CHEMICAL ENGINEERING TRANSACTIONS, 21 (2010) 1405-1410.

[8]A.A. Kiss, J. David, P. Suszwalak, Enhanced bioethanol dehydration by extractive and azeotropic distillation in dividing-wall columns, Separation and Purification Technology, 86 (2012) 70-78.

[9]M. Gadalla, Z. Olujic, A. de Rijke, P.J. Jansens, Reducing C02 emissions of internally heat-integrated distillation columns for separation of close boiling mixtures, Energy, 31 (2006) 2409-2417.

Claims

Claims

1 . A method of separating carbon dioxide from a process stream and

condensing a primary component of the process stream, the method comprising: providing a process stream comprising gaseous carbon dioxide and further comprising a primary component, wherein the process stream is at a first

temperature and a first pressure;

cooling the process stream to at or below the condensation temperature of the primary component in the process stream;

separating any gases from the process stream that did not condense during cooling the process stream to at or below the condensation temperature of the primary component to form a first separated gaseous stream;

cooling the process stream further to at or below the frost point of carbon dioxide in the process stream, thereby forming solid carbon dioxide; and

separating physically solid carbon dioxide from the process stream to form a separated solid carbon dioxide slurry stream and a liquid primary component stream.

2. The method of claim 1 , further comprising:

cooling the process stream to a second temperature, wherein the second temperature is above the melting point of pure carbon dioxide at the pressure of the process stream; and

separating any liquids from the process stream that condensed during cooling the process stream to the second temperature to form a first separated liquids stream.

3. The method of claim 2, wherein the second temperature is above and near the melting point of pure carbon dioxide at the first pressure.

4. The method of claim 3, wherein above and near comprises less than about 15° C above, less than about 10° C above, and less than about 5° C above.

5. The method of any one of claims 2-4, wherein the first separated liquids stream comprises condensed components.

6. The method of claim 5, wherein the first separated liquids stream comprises condensed natural gas liquids.

7. The method of claim 6, further comprising warming the combined separated liquids stream to about the first temperature.

8. The method of claim 7, wherein warming the first separated liquids stream cools the process stream, a separate refrigeration loop, or both, at one or more locations.

9. The method of any one of claims 1 -8, wherein the primary component has a critical temperature higher than -85° C, -90° C, 95° C, or -100° C.

10. The method of any one of claims 1 -9, further comprising cooling the process stream to a third temperature, wherein the third temperature is above and near the condensation temperature of the primary component at the pressure of the process stream.

1 1 . The method of claim 10, wherein above and near comprises less than about 15° C above, less than about 10° C above, and less than about 5° C above.

12. The method of claim 10 or claim 1 1 , further comprising separating any liquids from the process stream that condensed during cooling the process stream to the third temperature to form a second separated liquids stream.

13. The method of claim 12, wherein the second separated liquids stream comprises condensed components.

14. The method of claim 13, wherein the second separated liquids stream comprises condensed natural gas liquids.

15. The method of any one of claims 12-14, further comprising combining the second separated liquids stream with the first separated liquids stream to form a combined separated liquids stream.

16. The method of claim 15, further comprising warming the combined separated liquids stream to about the first temperature.

17. The method of claim 16, wherein warming the combined separated liquids stream cools the process stream, a separate refrigeration loop, or both, at one or more locations.

18. The method of any one of claims 15-17, further comprising separating components of the combined separated liquids stream into separate product streams.

19. The method of any one of claims 10-18, wherein the third temperature is sufficiently above the condensation temperature of the primary component such that no condensate forms in which the primary component comprises more than 50% of the condensate.

20. The method of any one of claims 10-18, wherein the third temperature is sufficiently above the condensation temperature of the primary component such that no condensate forms in which the primary component comprises more than 25% of the condensate.

21 . The method of any one of claims 1 -20, wherein the liquid primary component stream comprises liquefied natural gas and at least a portion of the liquefied natural gas is transported to a distribution network, with or without further processing.

22. The method of any one of claims 1 -21 , wherein the first separated gaseous stream is not present.

23. The method of any one of claims 1 -22, wherein the first separated gaseous stream comprises carbon dioxide, trace components, or combinations thereof.

24. The method of any one of claims 1 -23, further comprising combining the first separated gaseous stream with the separated solid carbon dioxide stream to form a combined carbon dioxide stream.

25. The method of claim 24, further comprising warming the combined carbon dioxide stream to about the first temperature.

26. The method of claim 25, wherein warming the combined carbon dioxide stream cools the process stream, a separate refrigeration loop, or both, at one or more locations.

27. The method of any one of claims 1 -26, wherein the separated solid carbon dioxide stream comprises condensed natural gas liquids and further comprising separating the condensed natural gas liquids from the carbon dioxide.

28. The method of any one of claims 1 -27, wherein the first separated liquids stream is not present.

29. The method of any one of claims 1 -28, wherein the first separated liquids stream comprises primarily natural gas liquids.

30. The method of any one of claims 1 -29, further comprising warming the first separated liquids stream to about the first temperature and transporting the warmed first separated liquids.

31 . The method of claim 30, wherein warming the first separated liquids stream cools the process stream, a separate refrigeration loop, or both, at one or more locations.

32. The method of any one of claims 1 -31 , wherein cooling the process stream to at or below the frost point of carbon dioxide in the process stream comprises reducing the pressure of the process stream sufficient to vaporize a portion of the condensed primary component, thereby cooling the remainder of the process stream.

33. The method of claim 32, wherein reducing the pressure utilizes passing the process stream through a pressure regulating device.

34. The method of claim 32 or of claim 33, further comprising applying additional cooling to the process stream to desublimate or further desublimate solid carbon dioxide in the process stream.

35. The method of claim 34, wherein applying additional cooling comprises directly contacting the process stream with a colder contact gas stream or using a non-direct contact heat exchanger configured to remove desublimated carbon dioxide formed within the heat exchanger.

36. The method of any one of claims 1 -35, wherein cooling the process stream to at or below the frost point of carbon dioxide in the process stream comprises directly contacting the process stream with a colder contact gas stream or using a non-direct contact heat exchanger configured to remove desublimated carbon dioxide formed within the heat exchanger, without vaporizing a portion of the condensed primary component.

37. The method of claim 36, further comprising separating a warmed contact gas stream from a slurry of the condensed primary component and solid carbon dioxide.

38. The method of claim 37, further comprising removing saturated carbon dioxide vapor from the warmed contact gas stream.

39. The method of claim 37 or of claim 38, wherein the contact gas comprises nitrogen, air, a noble gas, carbon monoxide, or combinations thereof.

40. The method of any one of claims 1 -39, further comprising drying the process stream to remove moisture from the process stream prior to cooling the process stream to the second temperature.

41 . The method of any one of claims 1 -40, further comprising cooling the process stream to the first temperature using cooling water.

42. The method of any one of claims 1 -41 , wherein the process stream is raw and unfiltered at the first temperature and the first pressure.

43. The method of any one of claims 1 -42, wherein the process stream has been partially-conditioned to remove sulfur, moisture, other trace components, or combinations thereof, prior to being cooled.

44. The method of any one of claims 1 -43, wherein the primary component of the process stream comprises methane.

45. The method of any one of claims 1 -44, wherein the primary component of the process stream is not carbon dioxide.

46. The method of any one of claims 1 -45, wherein the liquid primary component stream comprises purified liquefied natural gas (LNG).

47. The method of claim 46, wherein the liquid primary component stream comprises less than about 2% carbon dioxide, less than about 1 % carbon dioxide, less than about 0.1 % carbon dioxide, or less than about 50 ppm carbon dioxide.

48. The method of any one of claims 1 -47, wherein the first pressure is about 25 bar to about 200 bar, about 50 bar to about 150 bar, or about 50 bar to about 100 bar.

49. A method of separating carbon dioxide from a process stream without condensing a primary component of the process stream, the method comprising: providing a process stream comprising gaseous carbon dioxide and further comprising a primary component, wherein the process stream is at a first

temperature and a first pressure;

reducing the temperature of the process stream to a temperature at or below the frost point of carbon dioxide in the process stream, by directly contacting the process stream with a colder contact liquid, thereby forming solid carbon dioxide in the contact liquid and forming a gaseous purified primary component stream; and separating physically solid carbon dioxide from the contact liquid to form a solid carbon dioxide slurry stream from a purified contact liquid stream.

50. The method of claim 49, further comprising:

cooling the process stream to a second temperature, wherein the second temperature is above the melting point of pure carbon dioxide at the pressure of the process stream and

separating any liquids from the process stream that condensed during cooling the process stream to the second temperature to form a first separated liquids stream.

51 . The method of claim 50, wherein the second temperature is above and near the melting point of pure carbon dioxide at the first pressure.

52. The method of claim 51 , wherein above and near comprises less than about 15° C above, less than about 10° C above, and less than about 5° C above.

53. The method of any one of claims 49-52, further comprising cooling the process stream to a third temperature, wherein the third temperature is above and near the frost point of carbon dioxide in the process stream, prior to forming solid carbon dioxide.

54. The method of claim 53, wherein above and near comprises less than about 15° C above, less than about 10° C above, and less than about 5° C above.

55. The method of claim 53 or of claim 54, wherein cooling the process stream to the third temperature condenses a portion of the process stream, such that the process stream comprises gas, vapor, condensed components, or a combination thereof, when forming solid carbon dioxide.

56. The method of any one of claims 53-55, wherein the condensed components of the process stream comprises condensed impurities, natural gas liquids, or combinations thereof.

57. The method of any one of claims 53-56, wherein the condensed components of the process stream comprise less than about 5%, less than about 4%, less than about 3%, less than about 2%, less than about 1 %, or about 0% of the process stream.

58. The method of any one of claims 53-57, wherein cooling the process stream to the third temperature does not condense a portion of the process stream.

59. The method of claim 58, wherein the process stream comprises dry natural gas.

60. The method of any one of claims 50-59, further comprising warming the first separated liquids stream to about the first temperature.

61 . The method of claim 60, wherein warming the first separated liquids stream cools the process stream, a separate refrigeration loop, or both, at one or more locations.

62. The method of any one of claims 50-61 , wherein the first separated liquids stream is not present.

63. The method of any one of claims 50-62, wherein the first separated liquids stream comprises primarily natural gas liquids.

64. The method of any one of claims 50-63, further comprising warming the first separated liquids stream to about the first temperature.

65. The method of claim 64, wherein warming the first separated liquids stream cools the process stream, a separate refrigeration loop, or both, at one or more locations.

66. The method of any one of claims 49-65, wherein at or below the frost point comprises less than about 45° C below the frost point, less than about 25° C below the frost point, and less than about 15° C below the frost point.

67. The method of any one of claims 49-66, wherein the solid carbon dioxide slurry stream comprises a slurry of solid carbon dioxide, the contact liquid, and any condensed components of the process stream.

68. The method of claim 67, further comprising separating solid carbon dioxide from the contact liquid and any condensed components.

69. The method of claim 68, wherein the contact liquid stream at steady-state comprises previously condensed components of the process stream.

70. The method of claim 69, further comprising separating out a portion of the contact liquid stream as a product stream and warming the product stream to about the first temperature.

71 . The method of claim 70, wherein warming the product stream cools the process stream, a separate refrigeration loop, or both, at one or more locations.

72. The method of any one of claims 68-71 , further comprising removing saturated carbon dioxide from the contact liquid.

73. The method of claim 72, wherein removing saturated carbon dioxide from the contact liquid comprises reducing the pressure of the contact liquid sufficient to vaporize some of the carbon dioxide and then repressurizing the contact liquid.

74. The method of any one of claims 49-73, wherein the primary component has a critical temperature lower than -85° C, -90° C, -95° C, or -100° C.

75. The method of claim 74, further comprising additional components with critical temperatures lower than -85° C, -90° C, -95° C, or -100° C.

76. The method of claim 75, wherein the primary component and the additional components are selected from carbon monoxide, nitrogen, and hydrogen.

77. The method of any one of claims 49-76, wherein the primary component has a critical temperature above -85° C.

78. The method of claim 77, wherein the primary component is methane.

79. The method of any one of claims 49-78, further comprising warming the purified gaseous primary component stream to about the first temperature.

80. The method of claim 79, wherein warming the purified gaseous primary component to about the first temperature comprises warming within about 10° C, about 5° C, or about 1 ° C of the first temperature.

81 . The method of claim 79 or claim 80, wherein warming the purified gaseous primary component stream cools the process stream, a separate refrigeration loop, or both, at one or more locations.

82. The method of any one of claims 49-81 , wherein the purified gaseous primary component stream comprises less than about 2% carbon dioxide, less than about 1 % carbon dioxide, less than about 0.1 % carbon dioxide, or less than 50 ppm carbon dioxide.

83. The method of any one of claims 49-82, wherein the first pressure is about 25 bar to about 200 bar, about 50 bar to about 150 bar, or about 50 bar to about 100 bar.

84. The method of any one of claims 49-83, wherein the process stream has been partially-conditioned to remove sulfur, moisture, other trace components, or combinations thereof, prior to being cooled.

85. A system for separating carbon dioxide from a process stream and

condensing a primary component of the process stream, the system comprising: a desublimation heat exchanger configured to receive a process stream comprising gaseous carbon dioxide and a primary component with a condensation temperature above the frost point of carbon dioxide at the pressure of the process stream, the desublimation heat exchanger further configured to cool the process stream to at or below the frost point of carbon dioxide in the process stream; and a solid-liquid separator configured to physically separate a solid carbon dioxide slurry stream from a liquid purified primary component stream.

86. The system of claim 85, wherein the desublimation heat exchanger comprises a direct contact heat exchanger configured to mix a colder contact gas with the process stream.

87. The system of claim 86, wherein the direct contact heat exchanger comprises a bubbler or a spray tower.

88. The system of claim 86 or claim 87, further comprising a first refrigeration system configured to circulate and cool the contact gas after the contact gas has been warmed in the desublimation heat exchanger.

89. The system of claim 88, further comprising a second refrigeration system in communication with the first refrigeration system and configured to remove heat from the contact gas.

90. The system of claim 89, wherein the second refrigeration system comprises a refrigerant and the second refrigeration system is configured to partially cool the refrigerant with a carbon dioxide stream, wherein the carbon dioxide stream is a slurry, a gas, or both.

91 . The system of any one of claims 85-90, further comprising a first heat exchanger configured to receive the process stream at a first temperature and a first pressure, the first heat exchanger configured to cool the process stream to a second temperature, wherein the second temperature is above and near the melting point of pure carbon dioxide at the first pressure of the process stream, and wherein the first heat exchanger is located upstream from the desublimation heat exchanger, relative to the process stream.

92. The system of claim 91 , wherein above and near comprises less than about 15° C above, less than about 10° C above, and less than about 5° C above.

93. The system of claim 91 or claim 92, further comprising a first separator configured to receive the process stream at the second temperature and separate any condensed liquids from the process stream and form a first separated liquids stream.

94. The system of claim 93, wherein the first separator and the first heat exchanger are part of a single unit operation.

95. The system of claim 93 or claim 94, wherein the first separator and the first heat exchanger are made of materials compatible with natural gas and natural gas liquids.

96. The system of any one of claims 93-95, wherein the first separator and the first heat exchanger are made of materials compatible with natural gas and natural gas liquids.

97. The system of any one of claims 93-95, wherein the first separator and the first heat exchanger are made of materials compatible with carbon monoxide and hydrogen gas and liquid tar.

98. The system of any one of claims 91 -97, wherein the first heat exchanger is further configured to receive the purified primary component stream, as a liquid, a gas, or both, and is further configured to warm the purified primary component stream while cooling the process stream.

99. The system of any one of claims 91 -98, wherein the first heat exchanger is further configured to receive the first separated liquid stream and warm the first separated liquid stream while cooling the process stream.

100. The system of any one of claims 91 -99, wherein the first heat exchanger is further configured to receive a carbon dioxide stream, either as a slurry, a gas, or both, and is configured to warm the carbon dioxide stream while cooling the process stream.

101. The system of any one of claims 85-100, further comprising a second heat exchanger configured to receive the process stream and cool the process stream to a third temperature, wherein the third temperature is above and near the

condensation temperature of the primary component at the pressure of the process stream, and wherein the second heat exchanger is located upstream from the desublimation heat exchanger, relative to the process stream.

102. The system of claim 101 , wherein above and near comprises less than about

15° C above, less than about 10° C above, and less than about 5° C above.

103. The system of claim 101 or claim 102, further comprising a second separator configured to receive the process stream at the third temperature and separate any condensed liquids from the process stream and form a second separated liquids stream.

104. The system of claim 103, wherein the second separator and the second heat exchanger are part of a single unit operation.

105. The system of claim 103 or claim 104, wherein the second separator and the second heat exchanger are made of materials compatible with natural gas, natural gas liquids, and liquid trace components, such as liquid mercury.

106. The system of any one of claims 101 -105, wherein the second heat

exchanger is further configured to receive the purified primary component stream, as a liquid, a gas, or both, and is further configured to warm the purified primary component stream while cooling the process stream.

107. The system of any one of claims 101 -106, wherein the second heat

exchanger is further configured to receive the second separated liquid stream and warm the second separated liquid stream while cooling the process stream.

108. The system of any one of claims 101 -107, wherein the second heat

exchanger is further configured to receive a carbon dioxide stream, either as a slurry, a gas, or both, and is configured to warm the carbon dioxide stream while cooling the process stream.

109. The system of any one of claims 85-108, further comprising a third heat exchanger configured to receive the process stream and cool the process stream to at or below the condensation temperature of the primary component at the pressure of the process stream and thereby condense at least a portion of the primary component, wherein the third heat exchanger is located upstream from the desublimation heat exchanger, relative to the process stream.

1 10. The system of claim 109, wherein at or below comprises less than about 15° C below, less than about 10° C below, and less than about 5° C below.

1 1 1. The system of claim 109 or claim 1 10, further comprising a third separator configured to receive the process stream and separate any non-condensed gases and vapors from the process stream.

1 12. The system of claim 1 1 1 , wherein the third separator and the third heat exchanger are part of a single unit operation.

1 13. The system of claim 1 1 1 or claim 1 12, wherein the third separator and the third heat exchanger are made of materials compatible with liquefied natural gas and carbon dioxide gas.

1 14. The system of any one of claims 109-1 13, wherein the third heat exchanger is further configured to receive the purified primary component stream, as a liquid, a gas, or both, and is further configured to warm the purified primary component stream while cooling the process stream.

1 15. The system of any one of claims 109-1 14, wherein the third heat exchanger is further configured to receive a carbon dioxide stream, either as a slurry, a gas, or both, and is configured to warm the carbon dioxide stream while cooling the process stream.

1 16. The system of any one of claims 85-1 15, further comprising a pressure regulating device and a control system configured to reduce the pressure of the process stream sufficient to vaporize a portion of the condensed primary component and thereby further cool the process stream.

1 17. The system of claim 1 16, wherein the pressure regulating device comprises a valve or a turbine.

1 18. The system of claim 1 16 or claim 1 17, wherein the pressure regulating device and the control system are configured to sufficiently vaporize the condensed primary component to cool the process stream to at or below the frost point of carbon dioxide in the process stream.

1 19. The system of any one of claims 85-1 18, further comprising one or more additional desublimation heat exchangers configured to cool the process stream to at or below the frost point of carbon dioxide in the process stream in conjunction with the desublimation heat exchanger.

120. The system of claim 1 19, further comprising one or more additional solid- liquid separators configured to separate solid carbon dioxide slurry streams from liquid purified primary component streams.

121. A system for separating carbon dioxide from a process stream without condensing a primary component of the process stream, the system comprising: a desublimation heat exchanger configured to receive a process stream comprising gaseous carbon dioxide and a primary component, configured to receive a colder contact liquid stream, configured to directly contact the process stream with the colder contact liquid stream and cool the process stream to at or below the frost point of carbon dioxide in the process stream, configured to produce a gaseous purified primary component stream, and configured to produce a solids-containing contact liquid stream; and

a solid-liquid separator configured to receive the solids-containing contact liquid stream and physically separate a solid carbon dioxide slurry stream from a purified contact liquid stream.

122. The system of claim 121 , wherein the desublimation heat exchanger comprises a bubbler or a spray tower.

123. The system of claim 121 or claim 122, further comprising a first refrigeration system configured to cool the purified contact liquid stream to form the colder contact liquid stream prior to introduction of the colder contact liquid stream to the

desublimation heat exchanger.

124. The system of claim 123, wherein the first refrigeration system comprises a refrigerant and the first refrigeration system is configured to partially cool the refrigerant with a carbon dioxide stream, wherein the carbon dioxide stream is a slurry, a gas, or both.

125. The system of claim 123 or claim 124, further comprising a pressure regulating device configured to reduce the pressure of the purified contact liquid stream, prior to cooling the purified contact liquid stream to form the colder contact liquid stream.

126. The system of any one of claims 121 -125, further comprising a desaturation system comprising:

a pressure regulating device configured to reduce the pressure of the purified contact liquid stream sufficient to vaporize additional carbon dioxide out of the stream;

a separator configured to separate vaporized carbon dioxide from the contact liquid; and

a pump configured to repressurize the contact liquid to form a further purified contact liquid stream.

127. The system of claim 126, wherein the desaturation system and a first refrigeration system are integrated such that the cooling of the contact liquid occurs prior to repressurization.

128. The system of any one of claims 121 -127, further comprising a first heat exchanger configured to receive the process stream at a first temperature and a first pressure, the first heat exchanger configured to cool the process stream to a second temperature, wherein the second temperature is above and near the melting point of pure carbon dioxide at the first pressure of the process stream, and wherein the first heat exchanger is located upstream from the desublimation heat exchanger, relative to the process stream.

129. The system of claim 128, wherein above and near comprises less than about 15° C above, less than about 10° C above, and less than about 5° C above.

130. The system of claim 128 or claim 129, further comprising a first separator configured to receive the process stream at the second temperature and separate any condensed liquids from the process stream and form a first separated liquids stream.

131. The system of claim 130, wherein the first separator and the first heat exchanger are part of a single unit operation.

132. The system of claim 130 or claim 131 , wherein the first separator and the first heat exchanger are made of materials compatible with natural gas and natural gas liquids.

133. The system of claim 130 or claim 131 , wherein the first separator and the first heat exchanger are made of materials compatible with carbon monoxide and hydrogen gas and liquid tar.

134. The system of any one of claims 128-133, wherein the first heat exchanger is further configured to receive the gaseous purified primary component stream and is further configured to warm the gaseous purified primary component stream while cooling the process stream.

135. The system of any one of claims 128-134, wherein the first heat exchanger is further configured to receive the first separated liquid stream and warm the first separated liquid stream while cooling the process stream.

136. The system of claim 135, wherein the first heat exchanger is further configured to receive the separated contact liquid stream in combination with a separated contact liquid stream and warm the combined stream while cooling the process stream.

137. The system of any one of claims 128-136, wherein the first heat exchanger is further configured to receive a carbon dioxide stream, either as a slurry, a gas, or both, and is configured to warm the carbon dioxide stream while cooling the process stream.

138. The system of any one of claims 121 -137, further comprising a second heat exchanger configured to receive the process stream and cool the process stream to a third temperature, wherein the third temperature is above and near the frost point of carbon dioxide in the process stream, and wherein the second heat exchanger is located upstream from the desublimation heat exchanger, relative to the process stream.

139. The system of claim 138, wherein above and near comprises less than about 15° C above, less than about 10° C above, and less than about 5° C above.

140. The system of claim 138 or claim 139, wherein the second heat exchanger is made of materials compatible with natural gas, natural gas liquids, and liquid trace components, such as liquid mercury.

141. The system of claim 138 or claim 139, wherein the second heat exchanger is made of materials compatible with carbon monoxide and hydrogen gas, and liquid trace components, such as liquid mercury.

142. The system of any one of claims 138-141 , wherein the desublimation heat exchanger is configured to receive the process stream from the second heat exchanger as a gas, vapor, condensed components, or a combination thereof.

143. The system of claim 142, wherein the desublimation heat exchanger is configured to mix any condensed components received from the second heat exchanger, and any condensed components formed in the desublimation heat exchanger, with the contact liquid.

144. The system of claim 143, wherein the desublimation heat exchanger and the solid-liquid separator are made of materials compatible with the contact liquid, when the contact liquid is comprised primarily of condensed components of the process stream.

145. The system of claim 143 or claim 144, further comprising a separator configured to separate off a portion of the contact liquid stream to form a separated contact liquid stream.

146. The system of claim 145, wherein the second heat exchanger is further configured to receive the separated contact liquid stream and warm the separated contact liquid stream while cooling the process stream.

147. The system of any one of claims 138-146, wherein the second heat exchanger is further configured to receive the purified primary component stream and is further configured to warm the purified primary component stream while cooling the process stream.

148. The system of any one of claims 138-147, wherein the second heat

exchanger is further configured to receive a carbon dioxide stream, either as a slurry, a gas, or both, and is configured to warm the carbon dioxide stream while cooling the process stream.

149. The system of any one of claims 138-148, wherein the second heat

exchanger is further configured to receive a first separated liquid stream of condensed components from a first heat exchanger and a first separator, wherein the second heat exchanger is configured to cool the first separated liquid stream prior to combination of the first separated liquid stream with a contact liquid of the desublimation heat exchanger.

150. The system of any one of claims 121 -149, further comprising one or more additional desublimation heat exchangers configured to cool the process stream to at or below the frost point of carbon dioxide in the process stream in conjunction with the desublimation heat exchanger.

151. The system of claim 150, further comprising one or more additional solid- liquid separators configured to separate solid carbon dioxide slurry streams from gaseous purified primary component streams.

152. A method of separating carbon dioxide and ethane, the method comprising: providing a feed stream comprising carbon dioxide, ethane, and higher molecular weight hydrocarbons;

introducing the feed stream into a first distillation column, wherein the first distillation column is sized and configured to provide a first distillate stream and a first bottoms stream, wherein the first distillate stream comprises substantially pure carbon dioxide;

introducing at least a portion of the first bottoms stream into a second distillation column, wherein the second distillation column is sized and configured to provide a second distillate stream and a second bottoms stream, wherein the second bottoms stream comprises higher molecular weight hydrocarbons and is

substantially free of carbon dioxide and ethane;

introducing at least a portion of the second bottoms stream as a solvent into the first distillation column, separate from the feed stream; and

introducing at least a portion of the second distillate stream into a third distillation column, wherein the third distillation column is sized and configured to provide a third distillate stream and a third bottoms stream, wherein the third bottoms stream comprises ethane and is substantially free of carbon dioxide and higher molecular weight hydrocarbons.

153. The method of claim 152, wherein the higher molecular weight hydrocarbons comprise propane, butane, pentane, any natural gas component less volatile than ethane, or combinations thereof.

154. The method of claim 152 or claim 153, wherein the first distillate stream comprises at least about 90% pure, about 91 % pure, about 92% pure, about 93% pure, about 94% pure, or about 95% pure carbon dioxide.

155. The method of any one of claims 152-154, wherein the first distillate stream is condensed and at least a portion refluxed to the first distillation column.

156. The method of claim 155, further comprising storing a portion of the condensed first distillate stream for use in other processes.

157. The method of any one of claims 152-156, wherein the first bottoms stream comprises a significant amount of carbon dioxide impurity.

158. The method of claim 157, wherein the significant amount of carbon dioxide impurity is about 3 wt% or more, about 4 wt% or more, about 5 wt% or more, about 6 wt% or more, about 7 wt% or more, about 8 wt% or more, about 9 wt% or more, or about 10 wt% or more.

159. The method of any one of claims 152-158, wherein the second distillate stream comprises ethane and a significant amount of carbon dioxide impurity.

160. The method of claim 159, wherein the significant amount of carbon dioxide impurity is about 3 wt% or more, about 4 wt% or more, about 5 wt% or more, about 6 wt% or more, about 7 wt% or more, about 8 wt% or more, about 9 wt% or more, or about 10 wt% or more.

161. The method of claim 159, wherein the second distillate stream is partially condensed and refluxed to the second distillation column and wherein the

uncondensed portion is the portion introduced to the third distillation column.

162. The method of any one of claims 152-161 , wherein the third distillate stream comprises a substantial amount of ethane and a substantial amount of carbon dioxide.

163. The method of claim 161 , further comprising combining at least a portion of the third distillate stream with the feed stream prior to introducing the feed stream into the first distillation column.

164. The method of claim 163, wherein the third distillate stream is partially condensed and refluxed to the third distillation column and wherein in the

uncondensed portion is the portion combined with the feed stream.

165. The method of any one of claims 152-164, wherein the third distillate stream comprises an azeotropic mixture of ethane and carbon dioxide.

166. The method of any one of claims 152-165, wherein the feed stream to the first distillation column comprises a bottoms stream from a demethanizer column.

167. The method of any one of claims 152-166, further comprising exchanging heat between the second bottoms stream and the third bottoms stream prior to introducing the portion of the second bottoms stream as a solvent into the first distillation column.

168. The method of any one of claims 152-167, further comprising exchanging heat between the second bottoms stream, the third distillate stream, and the third bottoms stream prior to introducing the portion of the second bottoms stream as a solvent into the first distillation column.

169. The method of any one of claims 152-168, wherein heat is not exchanged between the first distillate stream and the second bottoms stream.

170. A method of retrofitting an existing extractive distillation process comprising a first and second distillation column and configured to produce a substantially pure ethane distillate stream from the second distillation column, the method comprising: reconfiguring the first distillation column to provide a first bottoms stream comprising a significant amount of carbon dioxide impurity;

introducing at least a portion of a second bottoms stream of the second distillation column as a solvent stream to the first distillation column, separate from the feed stream; and

adding a third distillation column and introducing at least a portion of a second distillate stream of the second distillation column into the third distillation column, wherein the third distillation column is sized and configured to provide a third distillate stream and a third bottoms stream, wherein the third bottoms stream comprises ethane and is substantially free of carbon dioxide and higher molecular weight hydrocarbons.

171. The method of claim 170, further comprising combining at least a portion of the third distillate stream with the feed stream prior to introducing it to the first distillation column.

172. The method of claim 170 or claim 171 , wherein the second distillate stream comprises ethane and a significant amount of carbon dioxide impurity.

173. The method of claim 172, wherein the significant amount of carbon dioxide impurity is about 3 wt% or more, about 4 wt% or more, about 5 wt% or more, about 6 wt% or more, about 7 wt% or more, about 8 wt% or more, about 9 wt% or more, or about 10 wt% or more.

174. The method of any one of claims 170-173, wherein the second distillate stream is partially condensed and refluxed to the second distillation column and wherein the uncondensed portion is the portion introduced to the third distillation column.

175. The method of any one of claims 170-174, wherein the higher molecular weight hydrocarbons comprise propane, butane, pentane, any natural gas component less volatile than ethane, or combinations thereof.

176. The method of any one of claims 170-175, further comprising exchanging heat between the second bottoms stream and the third bottoms stream prior to introducing the portion of the second bottoms stream as a solvent into the first distillation column.

177. The method of any one of claims 170-176, further comprising exchanging heat between the second bottoms stream, the third distillate stream, and the third bottoms stream prior to introducing the portion of the second bottoms stream as a solvent into the first distillation column.

178. The method of any one of claims 170-177, wherein heat is not exchanged between the first distillate stream and the second bottoms stream.

179. An extractive distillation system, the system comprising:

a first distillation column configured to receive a feed stream and a separate recycle stream, and where the first distillation column is sized and configured to provide a first distillate stream and a first bottoms stream;

a second distillation column configured to receive the first bottoms stream, wherein the second distillation column is sized and configured to provide a second distillate stream and a second bottoms stream;

a diversion system configured to divert a portion of the second bottoms stream to the first distillation column as the recycle stream; and

a third distillation column configured to receive the second distillate stream, wherein the third distillation column is sized and configured to provide a third distillate stream and a third bottoms stream, wherein the third distillate stream is combined with the feed stream prior to introduction of the feed stream to the first distillation column.

180. The system of claim 179, wherein the feed stream is introduced within a lower 15% of the first distillation column.

181. The system of claim 179 or claim 180, wherein the recycle stream is introduced within an upper 15% of the first distillation column.

182. The system of any one of claims 179-181 , wherein the recycle stream is configured to be substantially condensed.

183. The system of any one of claims 179-182, wherein the first bottoms stream is introduced to the second distillation column within 15% of the middle of the second distillation column.

184. The system of any one of claims 179-183, wherein the second distillate stream is introduced to the third distillation column in an upper portion of the third distillation column.

185. The system of any one of claims 179-184, wherein the second distillate stream is configured to be substantially uncondensed.

186. The system of any one of claims 179-185, wherein the first distillate stream is configured to comprise substantially pure carbon dioxide.

187. The system of any one of claims 179-186, wherein the second bottoms stream is configured to comprise higher molecular weight hydrocarbons and to be substantially free of carbon dioxide and ethane.

188. The system of any one of claims 179-187, wherein the third bottoms stream is configured to comprise ethane and to be substantially free of carbon dioxide and higher molecular weight hydrocarbons.

189. A method of separating carbon dioxide from a process stream, the method comprising:

providing a process stream comprising gaseous carbon dioxide and further comprising a primary component and at least a secondary component;

cooling the process stream to at or below the frost point of carbon dioxide in the process stream, thereby forming solid carbon dioxide;

separating physically solid carbon dioxide from the process stream to form a separated solid carbon dioxide slurry stream and a liquid primary component stream; separating at least the secondary component and residual carbon dioxide from the liquid primary component stream; and

further separating the residual carbon dioxide from the secondary component using extractive distillation with a concentrator distillation column.

190. The method of claim 189, wherein the primary component is methane.

191. The method of claim 189 or claim 190, wherein the secondary component is ethane.